WELL TEST OPERATIONAL GUIDELINES.pdf

EXPRO

WELL TEST OPERATIONAL GUIDELINES

THIS MANUAL IS CONTROLLED

CONTROLLED COPY NO: _____

This manual and the information contained therein is the property of Expro. It must not be reproduced in whole or in part or otherwise disclosed without the prior consent in writing from the Manager Operations Support.

DISTRIBUTION LIST WELL TEST OPERATIONAL GUIDELINES Page 1 of 1

DISTRIBUTION LIST

TITLE

BASE

NAME

REF

OPERATIONS MANAGER PRODUCT SUPPORT SPECIALIST REGION DIRECTOR WELL TEST MANAGER WELL TEST SUPERVISOR PRODUCT DEVELOPMENT MANAGER OPERATIONS SUPPORT ENGINEER TECHNICAL MANAGER

HOUSTON ABERDEEN ABERDEEN ABERDEEN ABERDEEN ABERDEEN ABERDEEN ABERDEEN

T PARKIN N ASHTON G SIMS G MACDONALD D CLELAND C CRAIG R MAIR

001 003 004 030 027 028 011 034

AREA MANAGER WELL TEST SUPERVISOR OPERATIONS SUPPORT ENGINEER AREA MANAGER BUSINESS DEVELOPMENT MANAGER OPERATIONS SUPPORT MANAGER TECHNICAL SUPERVISOR HSEQC MANAGER WELL TEST SUPERVISOR WELL TEST SUPERVISOR TECHNICAL MANAGER BUSINESS DEVELOPMENT MANAGER AREA MANAGER WEST AFRICA

YARMOUTH YARMOUTH YARMOUTH SINGAPORE AFSU YARMOUTH AFSU AFSU AFSU AFSU AFSU AFSU AFSU

W OWEN A ROSS B GOOCH D BOWMAN M MOXEY G PEEK D WOODEN A HANNAH T JONES D BROWNE B LESTRANGE T CAMMERATA G MORGAN

008 010 012 015 013 031 014 079

REGION DIRECTOR OPERATIONS SUPPORT WELL TEST SUPERVISOR MAINTENANCE SUPERVISOR

HOLLAND HOLLAND HOLLAND HOLLAND

A KITCHENER M MEINSTER C SOUTER H EVERS

017 019 018 035

REGION DIRECTOR WELL TEST MANAGER REGIONAL OPERATIONS MANAGER

AUSTRALIA AUSTRALIA AUSTRALIA

S ASHTON K McCARTAN P BURTON

021

GENERAL MANAGER

NORWAY

J MACBEATH

005

OPERATIONS SUPERVISOR

TUNISIA

S DRAKE

009

OPERATIONS MANAGER

VIETNAM

S MOLLOY

022 & 023

GROUP MANAGER

NIGERIA

P STYLES

025

AREA MANAGER

CHINA

K CRAWFORD

007

BUSINESS DEVELOPMENT MANAGER

AMERICA

J LOAFMAN

029

P GHEZ

033

CLIENT ACCOUNT MANAGER OPERATIONS

LIBYA

S DRAKE

031

OPERATIONS

ABERDEEN

G MACDONALD

050 to 059

OPERATIONS

YARMOUTH

A ROSS

070 to 079

OPERATIONS

HOLLAND

N TIELENS

090 to 099 & 100 to 109

OPERATIONS

VIETNAM

S MOLLOY

110 to 119 & 130 to 134

OPERATIONS

AFRICA/FSU

D WOODEN

140 to 143

DATE:

OCTOBER 1999

ISSUE

2

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INTRODUCTION WELL TEST OPERATIONAL GUIDELINES Page 1 of 1

INTRODUCTION

This manual and revisions to it are under controlled distribution. Your name, and the number of the manual assigned to you, is kept on a master list maintained by the Surface & Environmental Systems Business Stream. Manuals for Operational use are assigned to the relevant Supervisor or Manager and it is their responsibility to ensure that all copies are updated with relevant amendments as issued. Receipt of this manual and subsequently revised pages shall be acknowledged in writing, by signing or initialling a copy of the transmittal memo and returning same to the Surface & Environmental Systems Business Stream. Outdated pages shall be destroyed and revised pages inserted in the manual. Each transmittal memo to you should be inserted in the manual behind the index. Un-registered copies of this manual are available for the use of Clients and prospective Clients. This manual is the property of The Expro Group and is to be returned upon request, or termination of its usefulness to the holder in conduct of Expro business. Custody of this manual may be transferred to another employee only with the knowledge and approval of the Surface & Environmental Systems Business Stream.

Surface & Environmental Systems Business Stream Aberdeen

DATE:

OCTOBER 1999

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AMENDMENTS & RE-ISSUES WELL TEST OPERATIONAL GUIDELINES Page 1 of 1

AMENDMENTS AND RE-ISSUES

1

The Testing & Environmental / Support Department reviews the Manual periodically with other departments to re-affirm its adequacy and conformity to current requirements. The minimum frequency for review of the Manual is once each 2 years.

2

Amendments to the Manual when requested are undertaken to reflect the current Company Safety Standards, legal requirements and additional, new and modified equipment. The amendments are made by replacement of applicable page(s). Each amendment page is identified by amendment number and date of each amendment. Amendments will be issued to the relevant sub-sub-section but only recorded on the Amendment Record of each sub-section.

3

Amendments are numbered consecutively until such times as a new issue incorporates all changes. When changes affect a considerable number of pages and in any case after not more than ten amendments to one issue, the Manual is re-issued. Issues are identified by letters in alphabetical order. Each issue cancels and replaces all previous issues and amendments.

4

The Amendment Record indicates all the amendments to the latest issue of the Manual.

5

All Operating Guidelines clearly state whether Operating Guidelines revisions servicing is provided, and a complete list of Manual holders is retained by the Manager, Operations Support. Amendments and re-issues of the Manual are automatically distributed to all registered holders of controlled copies.

6

Personnel wishing to propose amendments or additions to this manual should use the Proposal Form or similar, outlining the proposal and reasons for the amendment or addition. Proposals should be discussed in the first instance with the immediate Supervisor or Manager who will then pass the proposal to the Manager, Operations Support for consideration for inclusion. A sample Proposal Form can be found at the end of this manual.

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OCTOBER 1999

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AMENDMENT RECORD WELL TEST OPERATIONAL GUIDELINES Page 1 of 1

This procedure is a mandatory requirement and forms part of the Approved Well Test Operating Manual.

Alterations are not permitted without the prior approval of the Manager Operations Support.

AMENDMENT RECORD REV No.

DATE:

DATE

OCTOBER 1999

SUB-SECTION

BY

APPROVED

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SUMMARY OF CHANGE

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INDEX RECORD WELL TEST OPERATIONAL GUIDELINES Page 1 of 6

1.0

GENERAL OPERATING GUIDELINES 1.0 Risk Assessment 1.01 Responsibilities 1.02 Definitions 1.03 Procedure 1.04 Risk Ratings 1.05 Actions 1.06 Records 1.07 Updating Risk Assessments 1.1 Pre-Test Planning 1.1.1 Rig Visit 1.1.2 Engineering Requirements 1.1.3 Hazop Studies 1.1.4 Equipment Maintenance 1.1.5 Certification 1.1.6 Pre-Test Meetings 1.1.7 Equipment Requirements 1.1.8 Personnel Mobilisation 1.2 Pre-Test Work Site Guidelines 1.3 Rig Visit Guidelines 1.4 Gas Well Testing 1.4.1 Problems 1.4.2 Operating Procedures 1.5 Oil Well Testing 1.5.1 Problems 1.6 Solids Management 1.6.1 General / Solids Production 1.6.2 Sand “Frac-Clean ups” 1.6.3 Sand Separator 1.7 High Pressure/Temperature Well Testing 1.7.1 Problems 1.7.2 Sub-Surface Capability 1.7.3 Data Acquisition 1.7.4 15,000 psi Equipment 1.8 Foaming Oil Well Testing 1.8.1 Problems in Handling Foaming Oil 1.8.2 Operational Guidelines 1.9 Sour Gas Well Testing 1.9.1 Effect of H2S on Equipment 1.9.2 Stress Cracking 1.9.3 Equipment Fabrication 1.9.4 Pyrophoric Ignition 1.9.5 Training for Personnel Prior to Test 1.9.6 Operational Guidelines 1.9.7 Supervisory Responsibility 1.9.8 Artificial Resuscitation Methods 1.10 Acid Clean Up Procedures 1.11 Post Test Guidelines

TABLES 1-1 1-2

Toxicity of Hydrogen Sulphide Gas EXPRO's Recommended H2S Policy

APPENDIX 1 Fig. 1.1 Fig. 1.2 Fig. 1.3 Fig. 1.4 Fig. 1.5 Fig. 1.6

DATE:

Sour Gas Systems Sour Multiphase Systems Artificial Resuscitation Methods Artificial Resuscitation Methods Rig Visit Checklist (example) Risk Assessment Form

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2.0

PRESSURE TESTING GUIDELINES 2.1 Pressure for Field Pressure Testing 2.2 Duration of Pressure Tests and Mediums Used 2.3 Pressure Test Guidelines for Individual Items of Equipment 2.3.1 Surface Test Tree (on Deck) 2.3.2 Sand Filters 2.3.3 4 Valve/5 Valve Choke Manifolds 2.3.4 Heat Exchangers 2.3.5 Separators 2.3.6 Gas Diverters 2.3.7 Oil Diverters 2.3.8 Surge Tanks 2.3.9 Gauge Tanks 2.3.10 Freestanding Valves 2.3.11 Screwed Pressure Fittings 2.3.12 Erosion Probes ½" NPT 2.4 Example Pressure Test Diagrams 2.5 Post Pressure Testing Guidelines APPENDIX 2 Fig. 2.1 Fig. 2.2 Fig. 2.3 Fig. 2.4 Fig. 2.5 Fig. 2.6 Fig. 2.7 Fig. 2.8 Fig. 2.9 Fig. 2.10 Fig. 2.11 Fig. 2.12 Fig. 2.13 Fig. 2.14 Fig. 2.15 Fig. 2.16 Fig. 2.17

3.0

DATE:

Line Up for Flushing System Starboard and Port Oil and Gas Lines to Burner, Surge Tank Inlet Valves Function Test High Pilot (PSH) between Heat Exchanger and Separator and Actuated Surface Safety Valve Starboard and Port Oil and Gas Diverter Lines Oil Manifold Inlet Valves Surge Tank Body Separator Vessel and Outlet Valves Separator Inlet and Bypass Valves Heater Coils and Bypass Valves Heater Inlet and Bypass Valves Low Pressure Pilot (PSL2) Surface Safety Valve Choke Manifold and Downstream Valves Choke Manifold Upstream Valves Low Pressure Pilot (PSL1) Hydraulically Actuated Flow-Wing Valve and Flowhead Master Valve Remote ESD Stations

EQUIPMENT OPERATING GUIDELINES 3.1 Equipment Hook-up 3.1.1 Tubing Head Swivel 3.1.2 Surface Test Tree 3.1.3 Control Panel 3.1.4 Coflexip Hoses Hook-up 3.1.5 Pipework 3.1.6 Twin Pot Sand Filters 3.1.7 Data Headers 3.1.8 Choke Manifold Hook-up 3.1.9 Heat Exchanger 3.1.10 Relief Valve Skid 3.1.11 Phase Test Separator 3.1.12 Gas Diverter Manifold 3.1.13 Oil Manifold 3.1.14 Gauge/Surge Tank 3.1.15 Transfer Pump 3.1.16 Burner Booms 3.1.17 Burner/Ignition System 3.1.18 Burner Heads 3.1.19 Pressurised Laboratories 3.1.20 Dead Weight Tester 3.1.21 Surface Pressure/Temperature Recorder 3.1.22 Texsteam Chemical Injection Pump 3.1.23 Steam Generator 3.1.24 Air Lines

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3.2

3.3 3.4 3.5 3.6

3.7

3.8 3.9 3.10

3.11

3.12 3.13

3.14 3.15 3.16

3.17

3.18

3.19

3.20 3.21

DATE:

Lower Master Valve 3.2.1 Manual Valve 3.2.2 Hydraulically Actuated Valve Temperature Sub Chemical Injection Sub Tubing Head Swivel Surface Test Tree 3.6.1 Hydraulically Actuated Valves 3.6.2 Manual Valves Control Panels 3.7.1 Resato SPP-10 Control Panel 3.7.2 Hydratron Single Circuit ESD Unit Surface Safety Valves Coflexip Hoses Pipework 3.10.1 Minimum Allowable Wall Thickness 3.10.2 Thickness Checking 3.10.3 Hammer Unions 3.10.4 Clamp Connections 3.10.5 Flanges 3.10.6 Relief Line Capacities Twin Pot Sandfilters 3.11.1 Equalising Pots 3.11.2 Diverting Flow via Duty Standard Pot 3.11.3 Switching from Duty to Standby Pot (Standard) Pots 3.11.4 Diverting Flow via Duty Pot (Double Block Pot) 3.11.5 Switching from Duty to Standby Pot (Double Block) Pots 3.11.6 Draining Standby Pot 3.11.7 Using the Dual Isolation System 3.11.8 Switching from Duty to Standby Pot Data Headers Chokes and Choke Manifolds 3.13.1 Choke Manifolds 3.13.2 McEvoy Model 'H2' 3.13.3 Foley Model 'FH2' 3.13.4 Masterflo Chokes Heat Exchangers Freestanding Relief Valves Gas, Oil and Water Separators 3.16.1 General Operating Guidelines 3.16.2 Setting Back Pressure with Wizard 4150 Controller 3.16.3 Lowering/Raising Orifice Plate 3.16.4 Setting Liquid Level with Fisher 2500 Controller 3.16.5 Setting Liquid Level with Fisher 2900 Controller 3.13.6 Diverting Flow via Liquid Meters 3.16.7 Reading Barton Recorder 3.16.8 Using Sight Glasses 3.16.9 Meter Factors 3.16.10 Shrinkage Factors Gas Diverter Manifolds 3.17.1 Operating Guidelines 3.17.2 To Switch Flares Oil Diverter Manifolds 3.18.1 Oil Flow from Separator to Burner 3.18.2 Oil Flow to Gauge/Surge Tank 3.18.3 Oil Manifold Operation to Pump Out Tank to Burner Surge/Gauge Tanks 3.19.1 Start-Up and Gauging Flow 3.19.3 To Switch Sides on both Surge and Gauge Tanks 3.19.4 To Pump Out one or both Components Transfer Pumps 3.20.1 Electrical Pumps 3.20.2 Air Driven Pump Diaphragm Pump Ignition Systems 3.21.1 ‘Magniter’ Ignition System 3.21.2 Diesel Ignition System 3.21.3 Electric Ignition System

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3.22 3.23 3.24

3.25

3.26

3.27

Burners 3.22.1 Supergreen Crude Oil Burner Maintenance Guidelines Pressurised Laboratories Ancillary Equipment 3.24.1 Deadweight Testers 3.24.2 Pressure/Temperature Recorders 3.24.3 Chemical Injection Pumps 3.24.4 Ranarex Gravitometer 3.24.5 Ultrasonic Thickness Gauges 3.24.6 Fisher 67FR Air Regulators 3.24.7 Pressure Gauges 3.24.8 Stick Thermometers Valves 3.25.1 McEvoy 3.25.2 Foley 3.25.3 Magnum Converted Third Party Equipment 3.26.1 Compressors 3.26.2 Steam Generators Proppant Knockout Vessel 3.27.1 Initial Job Start Up 3.27.2 End of Test Clean Out Procedures

TABLES 3-1 3-2 3-3 3-4 3-5 3-6 3-7 3-8 3-9 3-10 3-11 3-12 3-13 3-14 3-15

Required Number of Turns to Fully Open/Close a McEvoy Valve Rislan Hoses Coflon Hoses List of Hoses in Service Minimum Allowable Wall Thickness for A106B Steel Thickness Checking Typical Range of Unions Used by EXPRO API Rated Flange Pressure Ratings ASA Rated Flange Pressure Ratings Pipeline Capacities (mmscf/d) from High Pressure Relief Valves Pipeline Capacities (mmscf/d) from Heat Exchanger Pipeline Capacities (mmscf/d) from Separator Pipeline Capacities (mmscf/d) from Surge Tank Pressure Ratings of Gauge Required Number of Turns to Fully Open/Close a McEvoy Valve

APPENDIX 3 Fig. 3.1 Fig. 3.2 Fig. 3.3 Fig. 3.4 Fig. 3.5 Fig. 3.6 Fig. 3.7 Fig. 3.8 Fig. 3.9 Fig. 3.10 Fig. 3.11 Fig. 3.12 Fig. 3.13 Fig. 3.14 Fig. 3.15 Fig. 3.16 Fig. 3.17 Fig. 3.18 Fig. 3.19 Fig. 3.20 Fig. 3.21 Fig. 3.22 Fig. 3.23 Fig. 3.24 DATE:

Actuator Lock-Open Cap and Disc Pressure Pilot and Remote ESD Tie-in Handling Coflexip Hoses Preferred Hook-up on Semi-submersible Rigs Pipework Metal Band Barton Recorder Hook-up Sample Points Clean-up Choke Manifolds Separator Barton Hook-up Gas Diverter Hook-up Oil Manifold Hook-up Correct Installation of Dogs on Lines Enclosure Layout Rotational Direction of Impeller Typical Coflexip Hose Structure Hammer Union Mating Parts Clamp Connector Components Data Headers Flange Make-up Sequence Single Block Choke Manifolds Double Block Choke Manifolds Masterflo Micrometer Indicator Daniel Senior Orifice Meter Effect of Proportional Band on Liquid Level

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Fig. 3.25 Fig. 3.26 Fig. 3.27 Fig. 3.28 Fig. 3.29

Liquid Meters Set-up Shrinkage Tester Gas Diverter Manifold Oil Diverter Manifold Winding Teflon Tape on a Thread

APPENDIX 3A Fig 1- EXPRO 2" Supergreen Atomiser head Assembly Fig 2- EXPRO Lodge Ignition System (High Velocity) Fig 3- Typical Supergreen Burner Rig Up Fig 4- Fan Type Radiation Screen 4.0

TED090101 TED080703 TED090108 TED080601

SURFACE SAMPLING GUIDELINES 4.1 PVT Sampling 4.2 Measuring Gas S.G. 4.3 Measuring Liquid S.G. 4.4 Measuring BS&W 4.5 Measuring Salinity (Chlorides) 4.6 Measuring Viscosity 4.7 Measuring Cloud/Pour Point 4.8 Measuring Resitivity of Water 4.9 Using Draeger Tester APPENDIX 4 Fig. 4.1 Fig. 4.2 Fig. 4.3 Fig. 4.4 Fig. 4.5 Fig. 4.6

Gas PVT Sampling Hook-up Oil PVT Sampling Hook-up Atmospheric Sampling Hydrometer in Cylinder Use of Draeger Tester Inserting Draeger Tubes

5.0

SAFETY GUIDELINES 5.1 General Safety 5.1.1 General 5.1.2 Emergency 5.2 Hook-up and Rig Down 5.2.1 Hook-up 5.2.2 Rig Down 5.3 Pressure Testing 5.4 Surface Sampling 5.5 Safety of Personnel While Working on Burner Booms 5.6 Corrosive and Hazardous Substances

6.0

CONTINGENCY GUIDELINES 6.1 Equipment Failure 6.2 Hydrates 6.3 Leaks 6.4 Suspension of Operations Due to Bad Weather 6.4.1 On Semi-Submersible Rigs 6.4.2 On All Rigs 6.5 High Temperatures 6.6 Miscellaneous 6.6.1 Contingency Procedures 6.6.2 Surface Data Logger 6.6.3 Data Points 6.7 Leaking Daniels Senior Orifice Meter 6.8 H2S Leak 6.9 Choke Manifold TABLES 6-1

DATE:

Freezing Points of Glycol/Freshwater Mixes

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7.0

MULTI SENSOR RELIEF VALVE (MSRV) 7.1 Specifications and Features 7.1.1 MSRV Safety Head Drawing 7.1.2 MSRV Drawing 7.2 Dis-Assembly Procedures 7.3 Assembly Procedures 7.4 Parts List 7.5 Pressure and Function Tests Maintenance Level 1 7.5.1 Impulse System Pressure Test 7.5.2 Internal Body Test 7.5.3 Closed Ball Valve Pressure Test 7.5.4 Ball Valve Gas Leak Test 7.5.5 Seat Leakage Criteria as per API 527 Maintenance Level 2 7.5.6 Impulse System Pressure Test 7.5.7 Internal Body Test 7.5.8 Closed Ball Valve Pressure/Function Test 7.5.9 Ball Valve Gas Leak Test 7.5.10 Seat Leakage Criteria as per API 527 7.6 Onshore - Maintenance Level 3 7.6.1 Impulse System Pressure Tests 7.6.2 Internal Body Test 7.6.3 Ball Valve Pressure/Function Test 7.6.4 Ball Valve - Gas Leak Test Seat Leakage Criteria as per API 527 Post Operations Function Test 7.7 Installation and Testing of Rupture Disc 7.7.1 Onsite Testing - Rupture Disc Installed 7.8 Operations with Emergency Shutdown System 7.8.1 Installation 7.8.2 Operation Principle 7.9 Contingency Procedures 7.9.1 Onsite Pressure Testing - Valve Leaks 7.9.2 Well Operations - Valve Activated APPENDIX 7

DATE:

Fig 7.1 Fig 7.2

10K MSRV Job Card MSRV Spare Parts List

Fig 7.3

Drawing Index Fig 7.3.1 MSRV General Assembly TED180101 Fig 7.3.2 MSRV Sensor System Application (Standard) TED180121 Fig 7.3.3 MSRV Downstream Sensor Installation (Heater to Separator) TED180126

Fig 7.4

Document Change Request Form - AB/AD/0501Rev2

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SECTION 1 GENERAL SUB SECTION 1.0 Page 1 of 3

RISK ASSESSMENT INTRODUCTION General hazards are identified in the Expro Group Safety Audit Procedure. This procedure detail the specific assessments made for operations. Specific assessments for manual handling and display screen equipment are contained in their relevant procedures. 1.0.1

RESPONSIBILITIES Base Managers are responsible for risk assessment being made in the areas they control. Senior crew members are responsible for carrying out on the spot risk assessments for all operational activities that are considered to be outside the scope of a normal well test/wireline operation. All "on the spot" assessments will be approved/authorised by senior base management prior to work commencement. The Safety department will support the Manager in making the assessment. Staff are responsible to co-operate with the assessments.

1.0.2

DEFINITIONS 1.

Risk Assessment A risk assessment consists essentially of an identification of the hazards present in an operation and an estimate of the extent of the risks involved, taking into account whatever precautions are already being taken.

2.

Hazard A hazard is an incident with the potential to cause harm.

3.

Risk Risk is the likelihood of the potential hazard being realised.

1.0.3

PROCEDURE The Base manager ensures a list of all hazards is prepared. An initial assessment of the risk from the hazards is then made using the Expro risk assessment form - see Appendix 1. The detail required in the assessment report will vary greatly, depending upon the nature of the particular hazard identified. In carrying out this exercise a 'risk rating' number has been arrived at, this is achieved in the following manner. Establish a probable frequency rating. To do this use the following scale: 1. 2. 3. 4. 5.

A highly improbable frequency occurrence. A remotely possible but known occurrence. An occasional occurrence. A fairly frequent occurrence. A frequent and regular occurrence.

Now establish a potential severity rating for the identified hazard using the following scale: 1. 2. 3. 4. 5. 6.

DATE:

OCTOBER 1999

Negligible Injuries. Minor Injuries. Major Injuries. Single Fatality Multiple Fatality. Multiple Fatality (including ones off site).

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WELL TEST OPERATIONAL GUIDELINES

1.0

RISK ASSESSMENT 1.0.3

PROCEDURE (CONT'D) Compile a risk rating number, using the table (see below) multiply the numbers derived from steps above. The risk rating enables the most serious hazard (those with the highest risk rating number) to be considered first. NOTE:

The scales listed above are included on the reverse side of the Risk Assessment Form.

SEVERITY

1.0.4

6

5

4

3

2

1

5

30

25

20

15

10

5

4

24

20

16

12

8

4

3

18

15

12

9

6

3

2

12

10

8

6

4

2

1

6

5

4

3

2

1

RISK RATINGS Activities with a risk rating of 0-6 would generally be regarded as no further action required. The assessment may also adequately cover a number of straightforward hazards. Activities with a risk rating of 7-15 will require an individual risk assessment being carried out detailing: -

The nature of the hazard The degree of risk from the hazard The people affected The precautions taken The information and training required.

Activities with a risk rating of 15-30 will require a very detailed risk assessment and where necessary, a detailed written safe system of work, which must identify all actions required to control the hazard. 1.0.5

ACTIONS Actions should where possible, aim to prevent the risk at source by making machinery or operations safer, or to control the risk by developing safe system of work, or as a last resort, providing personnel protection. Staff must be provided with relevant information and training on risks, preventative and protective measures, and emergency arrangements. There are a number of established safety procedures in this manual to help with these assessments. Where existing procedures do not cover the required assessment and the base manager decides he is unable to make a comprehensive assessment, then the safety department is available for assistance.

1.0.6

RECORDS An up to date record of assessments is maintained by the base manager.

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SECTION 1 GENERAL SUB SECTION 1.0 Page 3 of 3

RISK ASSESSMENT 1.0.7

UPDATING RISK ASSESSMENTS Risk assessments are revised: -

When there are changes to equipment or in operations Following accident and dangerous occurrences When safety/quality audits identify new hazards

It is the responsibility of the base manager to ensure that an annual review is made of hazards and risk assessments. Copies of revised risk assessments will be sent to the manager quality assurance & safety, who will be responsible for the re-distribution of the assessments to all group locations.

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1.1

SECTION 1 GENERAL SUB SECTION 1.1 Page 1 of 5

PRE-TEST PLANNING This involves many departments from operations, engineering, materials, quality assurance and maintenance to provide suitable equipment to be shipped for a well test. The sequence of events prior to a test will generally be as follows:1.

EXPRO awarded contract for well testing work.

2.

Meetings between EXPRO and the client will be carried out as required, throughout the term of the contract, to ensure the smooth running of operations to the clients’ satisfaction.

3.

Rig visit will be carried out if files on rig not up-to-date or if the well test will be of a non-standard nature.

4.

Operating company calls for equipment for a forthcoming well test. EXPRO will organise third party equipment to be used on test e.g. steam generators etc.

5.

The relevant operations supervisor / manager is responsible for producing proposed layout and P.I. / flow diagrams for certification. NOTE:

Equipment Selection; All components and equipment to be used on exploration wells which shall be exposed to a combination of pressure and hydrocarbons must be suitable for sour service to the material requirements as defined in NACE MR-01-75. In certain cases a Hazop study will have been attended. All relief lines, safety devices etc. will have been sized to expected well parameters (provided by operating company).

6.

Routine maintenance is carried out on all equipment to maintain a pool of equipment ready to be shipped offshore at short notice. Specific equipment will be assigned to the particular well test and a certification package compiled, which will include the diagrams and information such as chemical data sheets. This package will be submitted for approval by the relevant certifying authority. NOTE: Release notes for equipment may be issued by the rig certifying authority e.g. DNV. These may be issued where the certifying body is not willing to certify some equipment for a year, but are willing to certify it for one job e.g. if not sure that pipework is H2S rated then it may be certified for a 'sweet' test and have hardness checks etc. carried out before the full certification is accorded.

7.

A pre-test meeting may take place involving the well test supervisor or equivalent.

8.

When equipment is required it will be shipped to rig (this will often be around the time when the liner / casing string is set). NOTE: Consideration will obviously have to be given to distances that the equipment must be transported, and the length of time it will take. It may be the case that the equipment will have been shipped before the logs have been viewed resulting in a change of equipment required or possibly, in the case of a dry hole, the demobilisation of the equipment.

DATE:

9.

Operating company will call for well test personnel.

10.

Operations will mobilise a well test crew for equipment rig up.

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SECTION 1 GENERAL SUB SECTION 1.1 Page 2 of 5

PRE-TEST PLANNING POINTS DISCUSSED IN MORE DETAIL

1.1.1

RIG VISIT Once it has been decided that a well test will take place on a rig (or platform) then a rig visit will take place. This rig visit is to obtain at first hand information required for the success of a well testing programme and to overcome any problems in the planning stage, thus preventing possible delays at a more critical stage. The well tester carrying out the rig visit is expected to carry out the following:1.

Initially make contact with operating and drilling company representatives to discuss the well testing program to take place.

2.

To establish the equipment required to carry out that programme.

3.

Establish where the equipment will be sited in relation to safe access and exit, and the relative proximity of hazardous areas for that particular installation.

NOTE:

The safe routing of flowlines should also be considered.

4.

Survey the flare boom installation i.e. take measurements required to hang booms and note any problems. From the information gained on the rig visit a proposed layout diagram, boom loading diagram and/or a flow diagram/process and instrumentation diagram will be produced for certification by the rig certifying authority. Prior to producing these diagrams, Engineering will have carried out a study into the required size of relief lines and what safety devices should be installed and include these on the relevant diagrams. A copy will also be passed to the operating and drilling companies for their approval. A file will be established for the rig for future reference and will be updated if future visits are carried out.

1.1.2

ENGINEERING REQUIREMENTS 1.

To size relief valves, lines, safety devices, etc. to reduce process pressure below the equipment MAWP and to ensure that all pipework and equipment will remain within specification, in a worst case scenario.

2.

To produce required diagrams for operating company, which may be of the following:Equipment Layout Diagram This diagram's main purpose is to highlight the rig's hazardous areas (around vents, electrical supply points etc.) and add the hazardous areas around the well test equipment. This diagram will be submitted for approval to the rigs certifying body before the well test to ensure no safety regulations are infringed in the spotting of equipment.

NOTE:

DATE:

OCTOBER 1999

This drawing is for a proposed equipment layout, if for any reason, the equipment is relocated, it is the rig owner’s responsibility to inform the certifying authority.

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PRE-TEST PLANNING Equipment Process and Instrumentation Diagram (P and I.D.) This diagram shows the process flow and the instrumentation and safety devices attached to the well test equipment. These diagrams also have to be approved by the rigs certifying body. These diagrams are standardised but can be altered for specific well tests once the clients’ equipment requirements are known. There are also other constraints to be considered prior to the completion of these diagrams, in that when working offshore the available deck space will play a major part in determining where, exactly, the larger items of equipment are placed. Consideration should also be given to the layout of flowlines in order to reduce the amount of elbows and restrictions thus reducing turbulence and any pressure drop through the flowline. Flow Diagram This diagram is an elementary P and I.D. and shows the flow path through the well test equipment, with valve configuration and will include safety devices. The Engineering department will also attend HAZOP studies if required. 1.1.3

HAZOP STUDIES These are discussions to look at potential hazards of operations on a WHAT IF basis. i.e. if this happens what will be the result. They are attended by all the companies involved in well operations i.e. the operating, drilling and all service companies. A third party may also attend these discussions to put forth an independent point of view to promote discussion. Operations will be broken down into blocks and looked at in detail e.g. what are the consequences of opening this valve, could it create a hazard. This will be carried out for the complete process train of the proposed well programme.

1.1.4

EQUIPMENT MAINTENANCE Routine maintenance procedures have been drawn up which are carried out on all equipment prior to shipping for a well test. Generally this maintenance will include the following: a) b) c) d) e) f) g) h)

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OCTOBER 1999

Visually inspected Internal inspected where applicable Thickness checked where applicable (when abrasive materials have been flowed through the equipment or when a survey is required eg. a major survey). Pressure tested Non-routine repairs carried out as required Paint and corrosion protection applied as per EXPRO maintenance procedures. Slings inspected Prepared for shipping

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PRE-TEST PLANNING 1.1.5

CERTIFICATION Certification is carried out on all equipment and is done on a 5 yearly (major) and yearly (annual) basis. The annual surveys include a visual inspection and pressure test to full working pressure to check the continuing functional ability of the equipment and any other requirements of the individual certifying authority. NOTE:

Before annual certification is issued the certifying authority must be satisfied as to the routine maintenance program carried out on the equipment throughout the year (which is recorded on maintenance records for each item of equipment).

Major surveys include all the features of an annual survey but generally speaking pressure tests are to 1-1/2 times maximum working pressure and the surveys may also include whatever the surveyor deems necessary eg. hardness checks etc., dependant on the equipment's service history.

It should be noted that annual surveys have a 3-month period of grace after the 12 month period to allow for equipment which is offshore on a long term contract, where certification may run out, to continue to be used for the short term. If the contract is ongoing after the 3-month period of grace then the equipment must be changed out and re-certified. If the equipment is not certified within the 3-month period (eg. due to transportation delays) then it must have a full major survey carried out before it will be re-certified. This 3 month period is not intended to allow for equipment to be sent offshore, short term, after the certification has run out. 1.1.6

PRE-TEST MEETINGS These are usually held shortly before the actual start date of operations and involve the operating and drilling companies, and all the service companies who will carry out the operations during the course of the well test. From EXPRO's point of view these meetings are normally attended by the supervisor who will carry out the test. The purpose of these meetings is to run through the programme of operations and to discuss the safety aspects of these operations. It is also to interface the equipment requirements between the different service companies, to ensure that it is known who supplies what eg. the proper cross-overs etc. The well test supervisor will take the proposed drawings produced by the engineering department to the meeting and will be ready to discuss the nature of operations from EXPRO's point of view eg. the safety aspects with regards to the well test equipment. He should also expect to answer specific questions related to our equipment and queries as to how the equipment works. Another topic that may be discussed are environmental issues e.g. noise pollution, oil spills, black smoke, etc.

1.1.7

EQUIPMENT REQUIREMENTS The operations supervisor will have been liasing with the client from the outset as to the equipment required. Together with the workshop foreman, he will assign it for that particular job and also deal with any special requirements eg., third party equipment to be used, or any particular EXPRO equipment to be used eg. D30 vertical separator (for high deliverability wells).

Once the equipment has been selected, it will be logged on the ECS computer system for that job to ensure that the whereabouts of all equipment is known at all times. The Materials / Transport department will complete the relevant dangerous goods notes and ensure that all paperwork is in order (not including certification which will be the responsibility of the Quality Assurance department). The materials co-ordinator will also arrange for the transport of equipment to and from the required location of the client e.g. which docks etc., on the proper dates.

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PRE-TEST PLANNING

1.1.8

PERSONNEL MOBILISATION This will be carried out, in the numbers required, when requested by the operating company. Personnel will be provided with all the required safety clothing to comply with EXPRO's company safety policy and COSHH regulations. Generally once a test is known to be forthcoming personnel assigned to that job are placed on standby to go offshore. This requires that they regularly check with the office and leave contact numbers if they plan to be away from home, until told to stand down

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SECTION 1 GENERAL SUB SECTION 1.2 Page 1 of 1

PRE-TEST WORK SITE GUIDELINES On arrival at the work site the EXPRO supervisor in charge of the job should follow the guidelines below to ensure that all runs smoothly during the forthcoming well test. 1.

The Supervisor should introduce himself to the Company man / Drilling supervisor and discuss the test requirements. Also they should introduce themselves to any other people who may assist EXPRO during a well test, eg. the Barge Engineer, Crane Operator, etc.

2.

The equipment should be inspected on arrival to the rig, for damage in transit, in order to maximise the time for EXPRO to respond. Particular attention should be placed on the availability of required instrumentation.

3.

Work areas should be inspected to ensure equipment can be spotted as per the layout diagram, and escape routes decided upon.

4.

The separator should be checked, both for accessories (eg. orifice plates, etc.) and the operation of equipment. a)

Sight glasses are clear and allow liquid level to rise and fall.

b)

Dump valves stroke properly and travel correct distance.

c)

Liquid meters should be checked that they are not seized, gearing should be checked, (meter factors will be performed later).

d)

Check the float retainers are removed (if fitted) and floats are connected to displacer arms.

5.

The spares inventory should be checked along with availability of correct cross-overs.

6.

The chokes should be checked for a full set and any extras that may be required (eg. 1/64th increments during sand frac clean-ups).

7.

Pressure recorders such as Foxboro or Barton should be calibration checked and recalibrated if required.

NOTE: In the field it is not practical to recalibrate the temperature probe, due to the complicated nature of this process, but it should be checked with cold and hot sources to verify it's accuracy. Use a stick thermometer in the thermowell if the temperature probe is out of calibration.

DATE:

8.

Barton differential recorders should be calibration checked (both static and differential) and recalibrated if required. The correct plumbing of the Barton should also be checked (flange taps and upstream static pressure).

9.

The Data Logger / Edge system pressure transducers should be calibration checked and the correct functioning of the system confirmed. The operator of the DAS must be made aware of the expected well parameters, threshold values, etc.

10.

The heat exchanger if used (should be pre-heated to the required temperature, and the operation of the temperature controller checked.

11.

The supervisor should ensure that all EXPRO crew members are aware of the rig alarm system (audible and visual) and understand what each alarm is.

12.

The supervisor should also ensure that senior crew members have a knowledge of the permit-to-work system that work will be carried out under.

13.

Where required, the supervisor should ensure that all crew members know where safety equipment eg. B.A. sets etc. are located and ensure that all EXPRO crew know the escape routes and muster points.

14.

Paperwork and stationary supplies / computer and computer supplies (if used) should be checked to ensure that there is a plentiful supply and that the computer has not been damaged in transit.

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SECTION 1 GENERAL SUB SECTION 1.3 Page 1 of 1

RIG VISITS A rig visit should be performed if a test is to be carried out on a rig that EXPRO have not tested on before or have not tested on for some time. The purpose of this rig visit is to ensure that equipment can be spotted without problems, that tie in points to rig lines, etc. and whatever crossovers required are identified. It is also a time to meet with operating and drilling company representatives and to check out rig certification, e.g. of permanent piping, etc. The rig visit checklist should be completed (Refer to Fig. 1.5 for an example) as much as possible. This will enable base staff to plan equipment/flowline, etc. requirements. NOTE:

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The completed rig visit checklist forms part of the planning report that is submitted for Certifying Authority approval.

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SECTION 1 GENERAL SUB SECTION 1.4 Page 1 of 3

GAS WELL TESTING 1.4.1.

PROBLEMS 1.

LIQUID LOADING This problem usually occurs when testing low producing gas wells with high liquid-gas ratios. Indications of liquid loading are wide variations of surface pressures.

2.

HYDRATE FORMATION This problem occurs normally in a high-pressure gas well. Flow across chokes or separator back pressure valve may also plug off causing upstream pressure to rise. Chemicals such as glycol and methanol can be injected (upstream of any potentially large pressure drops) to prevent and inhibit hydrate formation. However if a heat exchanger is used, this problem can largely be eliminated by maintaining the well stream temperature above the hydrate formation temperature.

3.

WET GAS STREAMS Wet gas streams can cause inaccuracies when measuring the specific gravity of a gas. They also can cause instrument lines to 'freeze' in extreme cold climates if running off separator gas instead of air, differential recorders can 'freeze' also. Knock-out pots, possibly filled with steel wool or with wire mesh screens to assist liquid knockout from gas, can be used to overcome this. These pots must be blown down regularly.

4.

IRREGULAR FLOW A frequent difficulty encountered in measuring accurately, gas flow rates is the rapidly changing rate when a well 'slugs'. This type of flow can cause errors when reading differential recorder charts but can be partially overcome by increasing the proportional band setting on the back pressure controller (this will cause the BPV to stroke at less sensitive pressure changes and stop 'hunting'). Also the pulsation dampening screw on the DPU cell can be screwed in restricting the flow of oil between either side of the bellows. (Do not screw in more than 1 1/2 turns from fully closed or else no pen movement may be observed). The pulsation dampener can be found under the screw at the back of the DPU cell (model 199) and requires a 1/8" sized Allen Key to adjust. Clockwise adjustment reduces pulsation, anti-clockwise increases.

5.

SOUR (H2S) GAS Sour gas is extremely toxic, causing illness and death in relatively small atmospheric quantities. H2S procedures are fully covered under Section 1.9.

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SECTION 1 GENERAL SUB SECTION 1.4 Page 2 of 3

GAS WELL TESTING 1.4.2

OPERATING PROCEDURES The actual course of events may differ according to conditions on the rig at the actual time of operations and the clients Test Programme. ASSUMPTIONS a)

SAFE and Coiled Tubing Cutting valves (if either used) installed and function tested.

b)

Surface Test Tree installed with kill-wing and swab valves closed and master valve open.

c)

All down hole safety valve(s) open.

d)

Texteam pump function tested, and methanol available in sufficient quantity.

STABILISED CONDITIONS attained when:a)

For closed in periods build-up